Pioneer Southwest has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the internet at www.pioneersouthwest.com. Again, the internet site to access the slides related to today's call is www.pioneersouthwest.com. At the website select Investor then select Investor Presentations.

The partnership's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer Southwest are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer Southwest's news release on Page 2 of the slide presentation and in Pioneer Southwest's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to Pioneer Southwest's, Senior Vice President of Investor Relations, Frank Hopkins.

Frank Hopkins

Good day everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott will be the first speaker. He'll review the financial and operating highlights for the second quarter and update you on PSE's drilling program in the Spraberry field. Rich will then cover the second quarter financials in more detail and provide earnings guidance for the third quarter. After that, we'll open up the call for your questions.

With that, I'll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning or good afternoon for some. Slide number 3 on highlights. We had second quarter adjusted income of $17 million or $0.47 per unit. That does exclude our mark-to-market derivative gain of $48 million or $1.35 per common unit.

Production average a little over 7,100 barrels a day equivalent. It's down 7% versus the first quarter, reflecting primary reasons deferral by 300 barrels a day, due to unexpected NGL inventory built from unplanned third-party at Mont Belvieu, where the NGLs are fractionated. We expect to sell that inventory volumes over the reminder of 2012.

In addition, we had a loss of 220 barrels a day equivalent and result of the tight NGL fractionation capacity at Mont Belvieu. But we expect ethane rejection will continue for the remainder of the year.

But our nine wells placed on production during the second quarter, 23 wells year-to-date. Seven additional wells were awaiting completion. We continue to see great benefit from drilling deeper to the Lower Wolfcamp, Strawn and Atoka intervals in the program.

We expect to generate full year production growth about 8% compared to '11. Adjusted the guidance obviously reflects the impact of the expected ethane rejection for the remainder of the year.

Cash flow from operations of $27 million. With a distribution of $0.52 per unit for the second quarter, payable on August 9, as a record date of August 2. That equates to $2.08 per common unit on an annualized basis.

Going to Slide number 4, comment on our drilling program. We expect to drill somewhere between 50 to 55 wells and recomplete those wells. The three rig drilling program expect to spend somewhere between $110 million to $120 million.

We expect to drill almost all of our wells. We'll be going to the Strawn formation. We increased our acreage up from 60% to 85% of the acreage position as Strawn potential with approximately about 30,000 barrels of oil equivalent.

And then, 35% of our 2012 wells are expected to be drilled to the deeper Atoka interval. We've increased our acreage there for the potential of the MLP from 40% up to 70% of the acreages at Atoka potential. A typical Atoka well will add somewhere between 50,000 to 70,000 barrels of oil equivalent to our total EUR.

In addition, we've drilled four 20 acre spaced wells on production, four 20-acre in-field wells. The results are very similar to a 40-acre well for Lower Wolfcamp with the EUR of 140,000 barrels of oil equivalent. We'll drill three more between now and end of the year. Total inventory of 85 40-acre locations, over 1,200 20-acre locations, with current well cost of about $1.9 million.

Let me turn it over to Rich to talks about the earnings.

Rich Dealy

Thanks, Scott. I'm going to start on Slide 5. As Scott mentioned, net income of $65 million or $1.82 per common unit did include unrealized mark-to-market derivative gains of $48 million or $1.35, so adjusted $17 million or $0.47 per unit.

Now, looking at the bottom of Slide 5. Our Q2 results versus Q2 guidance, Scott talked about productions, so I'll pass over that. And production cost at $23.34. This is because of the ethane rejection $0.70 higher than it would have been without ethane rejection.

So that would have been around $22.64 per BOE. It does also include our estimate of ad valorem taxes being little bit higher in 2012, though 2011 just as they're based on 2011 commodity prices. The other items enlist on this page are all within the guidance range and what we would have expected going into the quarter.

Looking Slide 6, on third quarter guidance, production same as what we had going into the second quarter 7,400 to 7,900 BOE's per day. This does reflect the fact that we believe ethane rejection will continue for the rest of 2012, refracted it into our production cost to $20.50 million to $23.50 per BOE. And then the other items are very similar to what they've been in past quarters, therefore at third quarter.

Turning Slide 7, couple of noteworthy things here. We do have $69 million drawn on our credit facility, leading $231 million of availability under three-rig programs and acquisitions. And then our derivative position, continuous strong position with 80% of our remaining coverage for 2012, 65% in 2013 and 60% in 2014.

So with, that I'll stop there and we'll open up the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) We'll take the first question from Praneeth Satish with Wells Fargo.

Praneeth Satish - Wells Fargo

You mentioned that ethane rejection is expected to persist over the balance of the year. Could you just discuss why you expect that to occur, is that due to takeaway capacity constrains or something else?

Scott Sheffield

It's really the fractionation at Mont Belvieu that just got tight. Fractionation capacity down there, and so in order to preserve that remaining barrels were rejecting ethane into the gas stream. That's really not takeaway it's just capacity at Mont Belvieu.

Praneeth Satish - Wells Fargo

But that should get result by early 2013?

Scott Sheffield

Correct.

Praneeth Satish - Wells Fargo

And then the other question I had was just on thoughts around drop downs from PSE, has the thinking there changed at all?

Scott Sheffield

No. At this current time, the best opportunities for PSE is to drill the remaining 40-acre drilling locations and the 20-acre drilling locations to deliver the best returns, long term to PSE.

Operator

We'll take the next question from Jeff Strauss with Windover Capital.

Jeff Strauss - Windover Capital

Scott, I was wondering how you look at the distribution growth as going forward with a faster production and reserve growth expectation. If we've had, say 5% annual expectation of growth in the past and have grown distribution 1% to 2%, as we grow reserve and production at 8%. How should the investor look upon that going forward?

Scott Sheffield

I think, obviously commodity prices, one of the things we've talked about in the past, we do have 3,000 barrels a day that were hedged at $81 on a drop down to protect the distributions back, a couple of years ago. That runs out in 2013.

So when you look at 2014, and going beyond we have great hedges in place, you get more opportunity for more cash flow coming into PSE, with our current three-rig count. And so it allows us to evaluate increasing our distribution faster than we have over the last few quarters.

So I think going into '13, we would expect something like we have in the past, but going into '14 and '15, we have the chance depending on what commodity prices are to do something more aggressive or may be closer to our production growth target.

Operator

The next question comes from Aaron Terry with Kayne Anderson.

Aaron Terry - Kayne Anderson

You guys had mentioned in your then your PXD press release that you guys are going to be evaluating some of the northern portion of your Spraberry acreage in Midland and Martin County's. Can you guys talk through, whether or not that could potentially have any impact on PSE?

Rich Dealy

Yes, PSE does hold Wolfcamp rights and certain of their properties in those two counties. And so it could have some important data points for PSE. We probably at PXD level won't have those data points' results until, sometime the first half of 2013. At that point in time, we'll have to evaluate the opportunity for PSE to be able to participate some time, like '13 may be going into '14, with more cash flow coming into the entity of drilling it owns horizontal wells at that point in time.

Aaron Terry - Kayne Anderson

And then can you guys just clarify for me on of the things on the ethane rejection. I notice that gas volumes between Q1 and Q2 went down, which I guess I was expecting with ethane rejection that you would see a lift in your gas production, but a decrease in NGL production. Can you just kind of walk me through how that logic works and why the decrease in the gas volumes?

Scott Sheffield

Yes, I think the gas volume decrease is really just a function of what's happening in the field in our areas where we're at which has got some constraints on getting it which is higher pressure on gas facility. So that's the only reason why the gas, as you're exactly right that have higher BTU gas with the ethane being left in the gas, but the production plant is really just a function of field pressures.

Aaron Terry - Kayne Anderson

So as far as looking forward towards Q3 or Q4, do you expect to kind of get the pressure results so that you should see gas volumes closer to what we saw in Q1, and just the continued reduction in NGL volumes until the ethane rejection is resolved? Or do you expect to see continued problem from the gas pricing inside?

Scott Sheffield

I think we will see over the course of the remainder this year getting the pressure in the field in these areas fixed. So we have increasing direct gas production, as you'd expect.

Aaron Terry - Kayne Anderson

And then finally, I know also the oil realizations dropped, I think the Midland price differentials to WTI was down during the quarter. Was that the primary change to you guys or was there anything else from the field perspective that led to that wider different??

Scott Sheffield

Just pushing Midland differential was driving it.

Operator

And will go to John Razzano from RBC Capital Markets.

John Razzano - RBC Capital Markets

Just to expand a little bit on Aaron's line of questioning, do you have a ballpark estimate of what the net impact is of ethane rejection on volumes for the rest of the year.

Rich Dealy

It's going to be in that same rate it was in the second quarter about 220 BOEs a day.

John Razzano - RBC Capital Markets

So excluding that rejection impact, is it fair to say that because you've got flat production, going into the 3Q, that there is moderate level of organic growth underlying the portfolio.

Rich Dealy

That is correct.

Operator

And we will go next Kevin Smith with Raymond James.

Kevin Smith - Raymond James

Congrats on the nice 20-acre spaced wells. How far are we along in that process? Would you feel comfortable in with 20-acre space and more results and tight curves and things of that nature?

Scott Sheffield

We got four wells, excellent results. We have three more, we'll know by the end of the year, but PXD has done a lot more in itself at the parent levels. So we feel very confident. And so we have high confidence that the 20-acre inventory will work for PSE for a long period of time.

Kevin Smith - Raymond James

Is that something you know on IP rates or is that something, as far as communication is that something to show up later on the decline rates historically?

Rich Dealy

We need to watch them for good six months, but a typical well is only draining somewhere between three and six acres. So we're drilling on 20-acre spacing. So we've taken this field down over the last 30 years from 160 to 20s. It will probably go to 10-acre spacing at some point in 10 years from now, or 20 years from now.

Kevin Smith - Raymond James

And then it looks like you lowered your well count by about five wells, so is that correct. I think, you guys had 55 to 60, and now you're 50-50?

Scott Sheffield

Yes. We did lower a little bit just because, we're drilling more well deeper, so it's taking little bit longer.

Kevin Smith - Raymond James

The obviously the parents are reducing its Spraberry rig count. Do you have any comments on that and how does that effect anything that you guys are doing and how should I interpret it?

Scott Sheffield

We announced, seven to eight months ago that we were going to reduce our vertical program from 40 to 30 because of the ramp up of the horizontal programs. So we use did it a little bit earlier, so the 30 rigs we're running now, three of those are for PSE.

Kevin Smith - Raymond James

And then lastly, and I think you've already touched on this a little bit, but if you have any other I'd appreciate it. PXD is looking to raise capital through his JV process, and still looking to dropdown properties to PSE, really it's just is a dollar amount or do you have any sort of discussions about potentially raising capital that way, or is just PSE saying the rate returns just aren't going to be there, so we just would prefer not to even have those conversations.

Rich Dealy

First of all, we had to look at the price that PSE would have to pay to make any acquisition, whether it's outside or whether it's a drop down from PXD. I mean, PXD is getting 40% to 50% returns now. There is no why that somebody's going to sell deliver a 40% to 50% return. So the returns on the in-field drilling 40-acres and 20-acres, is just so much greater than acquisition. So that's the main driver.

The second driver, if we happen to do a drop down, the maximum we could do is a couple of hundred million dollars. The joint venture opportunity raises somewhere around $2 billion to $2.5 billion, potentially. So it's just too small of a opportunity, just to do a small drop down.

Operator

We'll go next to Michael Peterson with MLV & Company.

Michael Peterson - MLV & Company

Interested in your perspective on the NGL market, specifically if you could speak to differentials relative to crude, if you think that second quarter realizations are may be reflective of new paradigm in terms of pricing, or may be just a blip on the radar relative to prior periods.

Scott Sheffield

I think the past several quarters, we've been running 45% to a little bit above 50%. I think we're going to be in a range of 40% to 45% for a while, until we see what happens going to next winter of WTI.

Operator

It appears there are no further questions at this time. Mr. Hopkins, I'd like to turn the conference back to you for any additional or closing remarks.

Frank Hopkins

I'd like to thank everyone for joining us this quarter. Hopefully, we'll get a chance to see some of you out on the road before next quarter's earning call. Again, thanks for listening today.

Operator

That does conclude today's presentation. Thank you for your participation.

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